UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10-Q

 

 

For the quarterly period ended September 30, 2017

or

For the transition period from                to

Commission file number 001-33614

 

ULTRA PETROLEUM CORP.

(Exact name of registrant as specified in its charter)

 

 

(281) 876-0120

(Registrant’s telephone number, including area code)

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  YES ☑     NO ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  YES ☑     NO ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company”, and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):

 

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). YES ☐     NO ☑

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13, or 15 (d) of the Securities Exchange Act of 1934 subsequent to the distributions of securities under a plan confirmed by a court. YES ☑     NO ☐

The number of shares outstanding, without par value, of Ultra Petroleum Corp., outstanding as of October 25, 2017 was 196,346,736.

 

 

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TABLE OF CONTENTS

 

 

 

 

 

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PART I – FINANCIAL INFORMATION

ITEM 1 – FINANCIAL STATEMENTS

ULTRA PETROLEUM CORP.

CONSOLIDATED STATEMENTS OF OPERATIONS

 

 

See accompanying notes to consolidated financial statements.

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ULTRA PETROLEUM CORP.

CONSOLIDATED BALANCE SHEETS

 

 

See accompanying notes to consolidated financial statements.

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ULTRA PETROLEUM CORP.

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(Amounts in thousands of U. S. dollars, except share data)

 

 

See accompanying notes to consolidated financial statements.

 

Shareholders’ Equity Explanatory Note:

In conjunction with emergence from chapter 11 proceedings, the Company issued new Common Shares to holders of existing pre-petition Common Shares (the “Existing Common Shares”) at a conversion ratio of 0.521562 (the “New Equity”). As a result, the share counts have been adjusted to reflect this conversion as if it had occurred as of January 1, 2016.

Consistent with the Plan (defined below), 194,991,656 shares of New Equity were issued as follows:

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ULTRA PETROLEUM CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

 

See accompanying notes to consolidated financial statements.

 

 

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(All amounts in this Quarterly Report on Form 10-Q are expressed in thousands of U.S. dollars (except per share data) unless otherwise noted).

DESCRIPTION OF THE BUSINESS:

Ultra Petroleum Corp. (the “Company”) is an independent oil and gas company engaged in the development, production, operation, exploration and acquisition of oil and natural gas properties. The Company is incorporated under the laws of Yukon, Canada. The Company’s principal business activities are developing its long-life natural gas reserves in the Green River Basin of Wyoming – the Pinedale and Jonah fields, its oil reserves in the Uinta Basin in Utah and its natural gas reserves in the Appalachian Basin of Pennsylvania.

Chapter 11 Proceedings

Voluntary Reorganization Under Chapter 11

On April 29, 2016 (the “Petition Date”), the Company and its subsidiaries (collectively, the “Debtors”) filed voluntary petitions under chapter 11 of title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). Our chapter 11 cases were jointly administered under the caption In re Ultra Petroleum Corp., et al, Case No. 16-32202 (MI) (Bankr. S.D. Tex.).

On February 13, 2017, the Bankruptcy Court approved our amended Disclosure Statement (by order subsequently amended on February 21, 2017), on March 14, 2017, the Bankruptcy Court confirmed our Debtors’ Second Amended Joint Chapter 11 Plan of Reorganization (the “Plan”), and on April 12, 2017 (the “Effective Date”), we emerged from bankruptcy.

As a result of our improved financial condition and successful emergence from chapter 11 proceedings, we believe we now have sufficient liquidity to fund our future cash requirements for operations, capital expenditures and working capital purposes. As a result, substantial doubt no longer exists regarding the Company’s ability to meet its obligations as they become due within one year after the date that the financial statements are issued.  

Because we emerged from bankruptcy during the nine months ended September 30, 2017 and because we continue our work to reconcile, resolve and pay certain prepetition claims asserted against us during our chapter 11 cases, certain aspects of our chapter 11 cases are described below to provide context to our financial condition and results of operations for the period presented in this Quarterly Report on Form 10-Q.  Information about our chapter 11 cases is available at a website maintained by our claims agent, Epiq Systems (http://dm.epiq11.com/UPT/Docket).

In addition, because our operations and ability to execute our business remain subject to various risks and uncertainties, including risks and uncertainties related to our chapter 11 cases, readers are encouraged to review and consider the items described in Item 1A, “Risk Factors” in our Annual Report on Form 10-K for our fiscal year ended December 31, 2016 and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2017.

Plan Support Agreement, Rights Offering, Backstop Commitment Agreement and Exit Financing Commitment Letter

As previously disclosed:

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

Fresh Start Accounting

As previously disclosed, we are not required to apply fresh start accounting to our financial statements in connection with our emergence from bankruptcy because the reorganization value of our assets immediately prior to confirmation of the Plan exceeded our aggregate postpetition liabilities and allowed claims.

Liabilities Subject to Compromise

The following table reconciles the settlement of liabilities subject to compromise included in our Consolidated Balance Sheets from December 31, 2016 through the nine months ended September 30, 2017:

 

 

Bankruptcy Claims Resolution Process

The claims filed against us during our chapter 11 proceedings are voluminous. In addition, claimants may file amended or modified claims in the future, which modifications or amendments may be material. The claims resolution process is on-going, and the ultimate number and amount of prepetition claims are not presently known, nor can the ultimate recovery with respect to allowed claims be presently ascertained.

As a part of the claims resolution process, we are working to resolve differences between amounts we listed in information filed during our bankruptcy proceedings and the amounts of claims filed by our creditors. We have filed, and we will continue to file, objections with the Bankruptcy Court as necessary with respect to claims we believe should be disallowed.

Costs of Reorganization

We have incurred significant costs associated with our reorganization and the chapter 11 proceedings. We expect these costs, which are being expensed as incurred, have affected and may continue to significantly affect our results of operations. For additional information about the costs of our reorganization and chapter 11 proceedings, see “Reorganization items, net” below.

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

The following table summarizes the components included in Reorganization items, net in our Consolidated Statements of Operations for the three and nine months ended September 30, 2017 and 2016:

 

 

1.  SIGNIFICANT ACCOUNTING POLICIES:

The accompanying financial statements, other than the balance sheet data as of December 31, 2016, are unaudited and were prepared from the Company’s records, but do not include all disclosures required by U.S. Generally Accepted Accounting Principles (“GAAP”). Balance sheet data as of December 31, 2016 was derived from the Company’s audited financial statements. The Company’s management believes that these financial statements include all adjustments necessary for a fair presentation of the Company’s financial position and results of operations. All adjustments are of a normal and recurring nature unless specifically noted. The Company prepared these statements on a basis consistent with the Company’s annual audited statements and Regulation S-X. Regulation S-X allows the Company to omit some of the footnote and policy disclosures required by GAAP and normally included in annual reports on Form 10-K. You should read these interim financial statements together with the financial statements, summary of significant accounting policies and notes to the Company’s most recent annual report on Form 10-K.

(a) Basis of presentation and principles of consolidation:  The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. The Company presents its financial statements in accordance with GAAP. All inter-company transactions and balances have been eliminated upon consolidation.

(b) Cash and Cash Equivalents:  The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.

(c) Restricted Cash:  Restricted cash represents the funds we deposited in the $400.0 million reserve account, which is for the resolution of make-whole and postpetition interest claims (the “Reserve Fund”), as described in Note 8, and cash received by the Company from production sold where the final division of ownership of the production is unknown or in dispute.

(d) Accounts Receivable: Accounts receivable are stated at the historical carrying amount net of write-offs and an allowance for uncollectible accounts.  The carrying amount of the Company’s accounts receivable approximates fair value because of the short-term nature of the instruments. The Company routinely assesses the collectability of all material trade and other receivables.

(e) Property, Plant and Equipment:  Capital assets are recorded at cost and depreciated using the declining-balance method based on their respective useful life.

(f) Oil and Natural Gas Properties:  The Company uses the full cost method of accounting for exploration and development activities as defined by the Securities and Exchange Commission (“SEC”) Release No. 33-8995, Modernization of Oil and Gas Reporting Requirements (“SEC Release No. 33-8995”) and Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 932, Extractive Activities – Oil and Gas (“FASB ASC 932”). Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

oil and gas properties. This includes any internal costs that are directly related to exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. The carrying amount of oil and natural gas properties also includes estimated asset retirement costs recorded based on the fair value of the asset retirement obligation when incurred. Gain or loss on the sale or other disposition of oil and natural gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country.

The sum of net capitalized costs and estimated future development costs of oil and natural gas properties are amortized using the units-of-production method based on the Company’s proved reserves. Oil and natural gas reserves and production are converted into equivalent units based on relative energy content. Asset retirement costs are included in the base costs for calculating depletion.

Under the full cost method, costs of unevaluated properties and major development projects expected to require significant future costs may be excluded from capitalized costs being amortized. The Company excludes significant costs until proved reserves are found or until it is determined that the costs are impaired. The Company reviews its unproved leasehold costs quarterly or when management determines that events or circumstances indicate that the recorded carrying value of the unevaluated properties may not be recoverable. The fair values of unproved properties are evaluated utilizing a discounted net cash flows model based on management’s assumptions of future oil and gas production, commodity prices, operating and development costs, as well as appropriate discount rates. The estimated prices used in the cash flow analysis are determined by management based on forward price curves for the related commodities, adjusted for average historical location and quality differentials. Estimates of cash flows related to probable and possible reserves are reduced by additional risk-weighting factors. The amount of any impairment is transferred to the capitalized costs being amortized.

Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed quarterly, on a country-by-country basis, utilizing the average of prices in effect on the first day of the month for the preceding twelve-month period in accordance with SEC Release No. 33-8995. The ceiling limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved crude oil and natural gas reserves discounted at 10%, plus the lower of cost or market value of unproved properties, less any associated tax effects. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and results in a lower depletion, depreciation and amortization (“DD&A”) rate in future periods. A write-down may not be reversed in future periods even though higher oil and natural gas prices may subsequently increase the ceiling.  The Company did not incur a ceiling test write-down during the nine months ended September 30, 2017 or 2016.

(g) Inventories:  Inventory primarily includes the cost of pipe and production equipment that will be utilized during the 2017 drilling program and crude oil inventory.  Materials and supplies inventories are carried at lower of cost or market and include expenditures and other charges directly and indirectly incurred in bringing the inventory to its existing condition and location.  Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory cost.  The Company uses the weighted average method of recording its materials and supplies inventory.  Crude oil inventory is valued at lower of cost or market.

(h) Deferred Financing Costs: The Company follows ASU No. 2015-3, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs and includes the costs for issuing debt, including issuance discounts, except those related to the revolving credit facility, as a direct deduction from the carrying amount of the related debt liability. Costs related to the issuance of the revolving credit facility are recorded as an asset in the Consolidated Balance Sheets.

(i) Derivative Instruments and Hedging Activities:  The Company follows FASB ASC Topic 815, Derivatives and Hedging (“FASB ASC 815”). The Company records the fair value of its commodity derivatives as an asset or liability in the Consolidated Balance Sheets, and records the changes in the fair value of its commodity derivatives in the Consolidated Statements of Operations.  The Company does not offset the value of its derivative arrangements with the same counterparty. See Note 6 for additional details.

(j) Income Taxes:  Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Valuation allowances are recorded related to deferred tax assets based on the “more likely than not” criteria described in FASB ASC Topic 740, Income Taxes.  In addition, the Company recognizes the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit.

(k) Equity Interests: In accordance with the Plan, each of the Company’s equity interests outstanding prior to the Effective Date were cancelled and each such equity interest has no further force or effect after the Effective Date. Pursuant to the Plan, the holders of the Company’s common shares outstanding prior to the Effective Date (the “Existing Common Shares”) received (i) their proportionate distribution of New Equity and (ii) the right to participate in the Rights Offering. The holders of all other equity interests in the Company received no distribution under the Plan in respect thereof.

(l) Earnings Per Share:  Basic earnings per share is computed by dividing net earnings attributable to common stockholders by the weighted average number of common shares outstanding during each period. Diluted earnings per share is computed by adjusting the average number of common shares outstanding for the dilutive effect, if any, of common stock equivalents. The Company uses the treasury stock method to determine the dilutive effect.

In conjunction with our emergence from chapter 11, on April 12, 2017, the Company issued shares of New Equity to holders of Existing Common Shares at a conversion ratio of 0.521562. As a result, the basic and fully diluted share counts have been presented to reflect this conversion as if it had occurred as of January 1, 2016.

Share based payments subject to performance or market conditions are considered contingently issuable shares for purposes of calculating diluted earnings per share. Thus, they are not included in the diluted earnings per share denominator until the performance or market criteria are met. For the quarter and nine months ended September 30, 2017, the Company had 4.1 million contingently issuable shares that are not included in the diluted earnings per share denominator as the performance or market criteria have not been met (See Note 4). There were no contingently issuable shares outstanding for the quarter and nine months ended September 30, 2016.

 

 

(m) Use of Estimates:  Preparation of consolidated financial statements in accordance with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

(n) Share-Based Compensation:  The Company measures and recognizes compensation expense for all share-based payment awards made to employees and directors, including employee stock options, based on estimated fair values in accordance with FASB ASC Topic 718, Compensation – Stock Compensation.

(o) Fair Value Accounting:  The Company follows FASB ASC Topic 820, Fair Value Measurements and Disclosures (“FASB ASC 820”), which defines fair value, establishes a framework for measuring fair value under GAAP, and expands disclosures about fair value measurements. This statement applies under other accounting topics that require or permit fair value measurements.  See Note 7 for additional details.

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

(p) Asset Retirement Obligation:  The initial estimated retirement obligation of properties is recognized as a liability with an associated increase in oil and gas properties for the asset retirement cost. Accretion expense is recognized over the estimated productive life of the related assets. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from revisions of estimated inflation rates, changes in service and equipment costs and changes in the estimated timing of settling asset retirement obligations. As a full cost company, settlements for asset retirement obligations for abandonment are adjusted to the full cost pool.  The asset retirement obligation is included within other long-term obligations in the accompanying Consolidated Balance Sheets.  

(q) Revenue Recognition:  The Company generally sells oil and natural gas under both long-term and short-term agreements at prevailing market prices. The Company recognizes revenues when the oil and natural gas is delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectability is reasonably assured. The Company accounts for oil and natural gas sales using the “entitlements method.” Under the entitlements method, revenue is recorded based upon the Company’s ownership share of volumes sold, regardless of whether it has taken its ownership share of such volumes. Any amount received in excess of the Company’s share is treated as a liability. If the Company receives less than its entitled share, the underproduction is recorded as a receivable.

Make-up provisions and ultimate settlements of volume imbalances are generally governed by agreements between the Company and its partners with respect to specific properties or, in the absence of such agreements, through negotiation. The value of volumes over- or under-produced can change based on changes in commodity prices. The Company prefers the entitlements method of accounting for oil and natural gas sales because it allows for recognition of revenue based on its actual share of jointly owned production, results in better matching of revenue with related operating expenses, and provides balance sheet recognition of the estimated value of product imbalances.  The Company’s imbalance obligations as of September 30, 2017 and December 31, 2016 were immaterial.

(r) Other revenues: Other revenues are comprised of fees paid to us by the operators of the gas processing plants where our gas is processed in exchange for the liquids removed from our production.

(s) Capital Cost Accrual: The Company accrues for exploration and development costs in the period incurred, while payment may occur in a subsequent period.

(t) Reclassifications:  Certain amounts in the financial statements of prior periods have been reclassified to conform to the current period financial statement presentation.

(u) Deposits and Retainers: Deposits and retainers primarily consist of payments related to surety bonds as of December 31, 2016.

(v) Recent Accounting Pronouncements:

Statement of Cash Flows.  In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (“ASU No. 2016-18”). The guidance requires that an explanation is included in the cash flow statement of the change in the total of (1) cash, (2) cash equivalents, and (3) restricted cash or restricted cash equivalents. ASU No. 2016-18 also clarifies that transfers between cash, cash equivalents and restricted cash or restricted cash equivalents should not be reported as cash flow activities and requires the nature of the restrictions on cash, cash equivalents, and restricted cash or restricted cash equivalents to be disclosed. For public companies, the standard will take effect for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017 with earlier application permitted. The Company is still evaluating the impact of ASU No. 2016-18 on its consolidated financial statements.

Statement of Cash Flows.  In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230) (“ASU No. 2016-15”). The guidance requires that debt prepayment or debt extinguishment costs, including third-party costs, premiums paid, and other fees paid to lenders, be classified as cash outflows for financing activities. For public companies, the standard will take effect for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017 with earlier application permitted. The Company does not expect the adoption of ASU No. 2016-15 to have a material impact on its consolidated financial statements.

Leases.  In February 2016, the FASB issued ASU 2016-02, Leases (“ASU No. 2016-02”).  The guidance requires that lessees will be required to recognize assets and liabilities on the balance sheet for the rights and obligations created by all leases with terms of more than 12 months. The ASU will also require disclosures designed to give financial statement users information

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

on the amount, timing, and uncertainty of cash flows arising from leases. These disclosures include qualitative and quantitative information. For public companies, the standard will take effect for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018 with earlier application permitted. The Company is still evaluating the impact of ASU No. 2016-02 on its consolidated financial statements.

Stock Compensation.  In May 2017, the FASB issued ASU 2017-09, Compensation-Stock Compensation (Topic 718) (“ASU No. 2017-09”), which is intended to clarify and reduce diversity in practice and cost and complexity when applying the guidance in Topic 718, Compensation-Stock Compensation, to a change to the terms or conditions of a share-based payment award.  For public companies, the standard will take effect for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017 with earlier application permitted.  The Company does not expect the adoption of ASU No. 2017-09 to have a material impact on its consolidated financial statements.

Revenue from Contracts with Customers.  In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) and in 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), and ASU 2016-10, Revenues from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing, which supersede the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities-Oil and Gas-Revenue Recognition. The new standard requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services.

We are currently evaluating the provisions of ASU 2014-09 and assessing the impact, if any, it may have on our financial position and results of operations. As part of our assessment work to date, we have completed training of the new ASU’s revenue recognition model, dedicated resources to its implementation, and initiated contract review and documentation; including analyzing the standard’s impact on our contract portfolio, comparing historical accounting policies and practices to the requirements of the new standard, and identifying differences from applying the requirements of the new standards to our contracts.  We are evaluating the expanded disclosure requirements under the new standard and are also reviewing our processes, systems, and internal controls over financial reporting to ensure the appropriate information will be available for these disclosures.  While we are continuing to assess all potential impacts of the standard, we currently believe the most significant impacts relate to principal versus agent considerations and the use of the entitlements method for oil and natural gas sales, both of which are continuing to be evaluated by the Company.

The Company is required to adopt the new standards in the first quarter of 2018 using one of two application methods: retrospectively to each prior reporting period presented (full retrospective method), or retrospectively with the cumulative effect of initially applying the guidance recognized at the date of initial application (the modified retrospective method). The Company currently anticipates adopting the standard using the modified retrospective method.

2.  OIL AND GAS PROPERTIES AND EQUIPMENT:

 

 

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

3.  DEBT AND OTHER LONG-TERM OBLIGATIONS:

 

 

 

As previously disclosed in a Current Report on Form 8-K filed with the SEC on April 18, 2017, on the Effective Date, all principal, prepetition interest, and other undisputed amounts were paid in full for the amounts owed under the prepetition Credit Agreement and the prepetition Senior Notes shown in the table above and the Company’s obligations under the prepetition Credit Agreement and the prepetition Senior Notes were cancelled and extinguished.  The make-whole and postpetition interest claims related to the prepetition Credit Agreement and prepetition Senior Notes were settled during the quarter ended September 30, 2017, see Note 8 for additional details.  The claims related to the 2018 and 2024 Notes, shown in the table above were allowed in full, each claim holder received a distribution of our common stock in the amount of the applicable claim, and the Company’s obligations under the 2018 and 2024 Notes were cancelled and extinguished.

Ultra Resources, Inc.

Credit Agreement. On April 12, 2017, Ultra Resources, Inc. (“Ultra Resources”), as the borrower, entered into a Credit Agreement with the Company and UP Energy Corporation, as parent guarantors, with Bank of Montreal, as administrative agent, and with the other lenders party thereto from time to time (as amended, the “RBL Credit Agreement”), providing for a revolving credit facility (the “Revolving Credit Facility”) for an aggregate amount of $400.0 million and an initial borrowing base of $1.2 billion (which limits the aggregate amount of first lien debt under the Revolving Credit Facility and the Term Loan Facility (defined below)).  As previously disclosed in a Current Report Form 8-K filed with the SEC on September 19, 2017, the Bank of Montreal, as administrative agent, and the other lenders party thereto, approved an increase in the borrowing base under the RBL Credit Agreement from $1.2 billion to $1.4 billion as requested by the Company, which included an increase in the commitments under the RBL Credit Agreement to an aggregate amount of $425.0 million.  At September 30, 2017, Ultra Resources had $20.0 million in outstanding borrowings under the RBL Credit Agreement, total commitments under the RBL Credit Agreement of $425.0 million and a borrowing base of $1.4 billion.  There are no scheduled borrowing base redeterminations until April 1, 2018.

The Revolving Credit Facility has capacity for Ultra Resources to increase the commitments subject to certain conditions, and has $50.0 million of the commitments available for the issuance of letters of credit. The Revolving Credit Facility bears interest either at a rate equal to (a) a customary London interbank offered rate plus an applicable margin that varies from 250 to 350 basis points or (b) the base rate plus an applicable margin that varies from 150 to 250 basis points.  The interest rate remained the same for the Revolving Credit Facility subsequent to the approved commitments increase noted above.  The Revolving Credit Facility loans mature on January 12, 2022.

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

The RBL Credit Agreement requires Ultra Resources to maintain (i) an interest coverage ratio of 2.50 to 1.00; (ii) a current ratio, including the unused portion of the Revolving Credit Facility,  of 1.00 to 1.00; (iii) a consolidated net leverage ratio of (A) 4.25 to 1.00 as of the last day of any fiscal quarter ending on or before December 31, 2017 and (B) 4.00 to 1.00, as of the last day of any fiscal quarter thereafter; and (iv) after the Company has obtained investment grade rating an asset coverage ratio of 1.50 to 1.00. At September 30, 2017, Ultra Resources was in compliance with all of its debt covenants under the RBL Credit Agreement.

Ultra Resources is required to pay a commitment fee on the average daily unused portion of the Revolving Credit Facility, which varies based upon a borrowing base utilization grid. Ultra Resources is also required to pay customary letter of credit and fronting fees.

The RBL Credit Agreement also contains customary affirmative and negative covenants, including, among other things, as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), delivery of quarterly and annual financial statements and oil and gas engineering reports, maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens, indebtedness, asset dispositions, fundamental changes, restricted payments, hedging requirements and other customary covenants.

The RBL Credit Agreement contains customary events of default and remedies for credit facilities of this nature. If Ultra Resources does not comply with the financial and other covenants in the RBL Credit Agreement, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the RBL Credit Agreement and any outstanding unfunded commitments may be terminated.

Term Loan. On April 12, 2017, Ultra Resources, as borrower, entered into a Senior Secured Term Loan Agreement with the Company and UP Energy Corporation, as parent guarantors, Barclays Bank PLC, as administrative agent, and the other lenders party thereto (the “Term Loan Agreement”), providing for senior secured first lien term loans for an aggregate amount of $800.0 million consisting of an initial term loan in the amount of $600.0 million and an incremental term loan in the amount of $200.0 million to be drawn immediately after the funding of the initial term loan.  As part of the Term Loan agreement, Ultra Resources agreed to pay an original issue discount equal to one percent of the principal amount, which is included in the deferred financing costs noted above.  The Term Loan Agreement has capacity to increase the commitments subject to certain conditions.  

As previously disclosed in a Current Report on Form 8-K filed with the SEC on September 29, 2017, the Company closed an incremental senior secured term loan offering of $175.0 million.  As part of the closing, Ultra Resources agreed to pay an original issue discount equal to 0.25% of the principal amount.  The original issue discount of $0.4 million is included in the deferred financing costs noted above and is a direct deduction from the carrying amount of long-term debt.  At September 30, 2017, Ultra Resources had $975.0 million in outstanding borrowings under the Term Loan Agreement (the “Term Loan Facility”).

The Term Loan Facility bears interest either at a rate equal to (a) a customary London interbank offered rate plus 300 basis points or (b) the base rate plus 200 basis points.  The Term Loan Facility amortizes in equal quarterly installments in aggregate annual amounts equal to 0.25% of the aggregate principal amount beginning on June 30, 2019. The Term Loan Facility matures seven years after the Effective Date.

The Term Loan Facility is subject to mandatory prepayments and customary reinvestment rights. The mandatory prepayments include, without limitation, a prepayment requirement with the total net proceeds from certain asset sales and net proceeds on insurance received on account of any loss of Ultra Resources’ property or assets, in each case subject to certain exceptions. In addition, subject to certain exceptions, there is a prepayment requirement if the asset coverage ratio is less than 2.0 to 1.0. To the extent any mandatory prepayments are required, prepayments are applied to prepay the Term Loan Facility.

The Term Loan Agreement also contains customary affirmative and negative covenants, including as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), delivery of quarterly and annual financial statements and oil and gas engineering reports, maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens, indebtedness, asset dispositions, fundamental changes, restricted payments and other customary covenants. At September 30, 2017, Ultra Resources was in compliance with all of its debt covenants under the Term Loan Facility.

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The Term Loan Agreement contains customary events of default and remedies for credit facilities of this nature. If Ultra Resources does not comply with the financial and other covenants in the Term Loan Agreement, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the Term Loan Agreement.

Senior Notes. On April 12, 2017, the Company issued $700.0 million of its 6.875% senior notes due 2022 (the “2022 Notes”) and $500.0 million of its 7.125% senior notes due 2025 (the “2025 Notes,” and together with the 2022 Notes, the “Notes”) and entered into an Indenture, dated April 12, 2017 (the “Indenture”), among Ultra Resources, as issuer, the Company and its subsidiaries, as guarantors. The Notes are treated as a single class of securities under the Indenture.

The Notes have not been registered under the Securities Act of 1933, as amended (the “Securities Act”) or any state securities laws, and unless so registered, the securities may not be offered or sold in the United States except pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act and applicable state securities laws. The Notes may be resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act or to non-U.S. persons pursuant to Regulation S under the Securities Act.

The 2022 Notes will mature on April 15, 2022. The interest payment dates for the 2022 Notes are April 15 and October 15 of each year, commencing on October 15, 2017. The 2025 Notes will mature on April 15, 2025. The interest payment dates for the 2025 Notes are April 15 and October 15 of each year, commencing on October 15, 2017. Interest will be paid on the Notes from the issue date until maturity.  

Prior to April 15, 2019, Ultra Resources may, at any time or from time to time, redeem in the aggregate up to 35% of the aggregate principal amount of the 2022 Notes in an amount no greater than the net cash proceeds of certain equity offerings at a redemption price of 106.875% of the principal amount of the 2022 Notes, plus accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the original principal amount of the 2022 Notes remains outstanding and the redemption occurs within 180 days of the closing of such equity offering. In addition, before April 15, 2019, Ultra Resources may redeem all or a part of the 2022 Notes at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) a make-whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. In addition, on or after April 15, 2019, Ultra Resources may redeem all or a part of the 2022 Notes at redemption prices (expressed as percentages of principal amount) equal to 103.438% for the twelve-month period beginning on April 15, 2019, 101.719% for the twelve-month period beginning April 15, 2020, and 100.000% for the twelve-month period beginning April 15, 2021 and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date on the 2022 Notes.

Prior to April 15, 2020, Ultra Resources may, at any time or from time to time, redeem in the aggregate up to 35% of the aggregate principal amount of the 2025 Notes in an amount no greater than the net cash proceeds of certain equity offerings at a redemption price of 107.125% of the principal amount of the 2025 Notes, plus accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the original principal amount of the 2025 Notes remains outstanding and the redemption occurs within 180 days of the closing of such equity offering. In addition, before April 15, 2020, Ultra Resources may redeem all or a part of the 2025 Notes at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) a make-whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. In addition, on or after April 15, 2019, Ultra Resources may redeem all or a part of the 2025 Notes at redemption prices (expressed as percentages of principal amount) equal to 105.344% for the twelve-month period beginning on April 15, 2020, 103.563% for the twelve-month period beginning April 15, 2021, 101.781% for the twelve-month period beginning April 15, 2022, and 100.000% for the twelve-month period beginning April 15, 2023 and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date on the 2025 Notes.

If Ultra Resources experiences certain change of control triggering events set forth in the Indenture, each holder of the Notes may require Ultra Resources to repurchase all or a portion of its Notes for cash at a price equal to 101% of the aggregate principal amount of such Notes, plus any accrued but unpaid interest to the date of repurchase.

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(Unaudited)

 

The Indenture contains customary covenants that restrict the ability of Ultra Resources and the guarantors and certain of its subsidiaries to: (i) sell assets and subsidiary equity; (ii) incur indebtedness; (iii) create or incur certain liens; (iv) enter into affiliate agreements; (v) enter into agreements that restrict distribution from certain restricted subsidiaries and the consummation of mergers and consolidations; (vi) consolidate, merge or transfer all or substantially all of the assets of the Company or any Restricted Subsidiary (as defined in the Indenture); and (vii) create unrestricted subsidiaries. The covenants in the Indenture are subject to important exceptions and qualifications. Subject to conditions, the Indenture provides that the Company and its subsidiaries will no longer be subject to certain covenants when the Notes receive investment grade ratings from any two of S&P Global Ratings, Moody’s Investors Service, Inc., and Fitch Ratings, Inc. At September 30, 2017, Ultra Resources was in compliance with all of its debt covenants under the Notes.

The Indenture contains customary events of default (each, an “Event of Default”). Unless otherwise noted in the Indenture, upon a continuing Event of Default, the trustee under the Indenture (“the Trustee”), by notice to the Company, or the holders of at least 25% in principal amount of the then outstanding Notes, by notice to the Company and the Trustee, may, declare the Notes immediately due and payable, except that an Event of Default resulting from entry into a bankruptcy, insolvency or reorganization with respect to the Company, any Significant Subsidiary (as defined in the Indenture) or group of Restricted Subsidiaries (as defined in the Indenture), that taken together would constitute a Significant Subsidiary, will automatically cause the Notes to become due and payable.

Other long-term obligations:  These costs primarily relate to the long-term portion of production taxes payable and asset retirement obligations.

4.  SHARE BASED COMPENSATION:

Valuation and Expense Information 

 

 

 

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

Changes in Stock Options and Stock Options Outstanding

As provided in the Plan, all plans or programs calling for stock grants, stock issuances, stock reserves or stock options were cancelled as of the Effective Date and all outstanding awards established prior to the Effective Date were cancelled and extinguished as of the Effective Date.

Performance Share Plans:

2017 Stock Incentive Plan.  On the Effective Date, the Ultra Petroleum Corp. 2017 Stock Incentive Plan (“2017 Stock Incentive Plan”) was established pursuant to which 7.5% of the equity in the reorganized Company (on a fully-diluted/fully-distributed basis) is reserved for grants to be made from time to time to the directors, officers, and other employees of the reorganized Company (the “Reserve”). Also on the Effective Date, 40% of the Reserve (“Initial MIP Grants”) was granted to members of the board of directors, officers, and other employees of the reorganized Company subject to the conditions and performance requirements provided in the grants, including the limitations that one-third of the Initial MIP Grants will vest, if at all, at such time when the total enterprise value of the Company equals or exceeds $6.0 billion based upon the volume weighted average price of the common stock during a consecutive 30-day period, that one-third of the Initial MIP Grants will vest, if at all, at such time when the total enterprise value of the Company equals or exceeds 110% of $6.0 billion based upon the volume weighted average price of the common stock during a consecutive 30-day period, and, that if any Initial MIP Grants do not vest before the fifth anniversary of the Effective Date, such Initial MIP Grants shall automatically expire.  The balance of the Reserve is available to be granted by the Board from time to time.

Stock-Based Compensation Cost:

Modification. On the Effective Date, as provided in the Plan, all outstanding awards established prior to the Effective Date were cancelled and extinguished, and participants received no payment or other distribution on account of the outstanding awards. Under FASB ASC Topic 718, Compensation Cost – Stock Compensation (“FASB ASC 718”), the cancellation of an outstanding award of stock based compensation followed by the issuance of a replacement award is treated as a modification of the original award. The equity award cancellations and subsequent new grants by the Company were considered Type I, probable to probable modification. This type represents modifications where the award was likely to vest prior to modification and is still likely to vest after modification. For these types of modifications, the fair value of the award is assessed both prior to modification and after modification. If the fair value after modification exceeds the fair value prior to modification, incremental expense is generated and recognized over the remaining vesting period.

During the quarter ended September 30, 2017, the Board approved a modification to the Initial MIP Grants made under the 2017 Stock Incentive Plan.  Certain grants made during the second quarter to members of the Board of Directors of the Company for the portion of the Initial MIP Grants related to the $6.0 billion total enterprise value and the portion of the Initial MIP Grants related to the $6.6 total enterprise value were forfeited and cancelled by the Board. In addition, an Initial MIP Grant was made to two of the members of the Board of Directors as previously reported on Forms 4 filed with the SEC.  The related non-cash stock compensation expenses are reflected in general and administrative expenses in the Consolidated Statement of Operations.

Market-Based Condition Awards. When vesting of an award of stock-based compensation is dependent, at least in part, on the value of a company’s total equity, for purposes of FASB ASC 718, the award is considered to be subject to a “market condition”. Because the Company’s total equity value is a component of its enterprise value, the awards based on enterprise value are considered to be subject to a market condition. Unlike the valuation of an award that is subject to a service condition (i.e., time vested awards) or a performance condition that is not related to stock price, FASB ASC 718 requires the impact of the market condition to be considered when estimating the fair value of the award. As a result, we have used a Monte Carlo simulation model to estimate the fair value of the awards that include a market condition.

FASB ASC 718 requires the expense for an award of stock based compensation that is subject to a market condition that can be attained at any point during the performance period to be recognized over the shorter of (a) the period between the date of grant and the date the market condition is attained, and (b) the award’s derived service period. For purposes of FASB ASC 718, the derived service period represents the duration of the median of the distribution of share price paths on which the market condition is satisfied. That median is the middle share price path (the midpoint of the distribution of paths) on which the market condition is satisfied. The duration is the period of time from the service inception date to the expected date of market condition satisfaction. Compensation expense is recognized regardless of whether the market condition is actually satisfied.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

Expense. For the nine months ended September 30, 2017, the Company recognized $34.2 million in pre-tax compensation expense, of which $32.9 million related to the Initial MIP Grants. During the nine months ended September 30, 2016, the Company recognized $4.0 million in pre-tax compensation expense, of which $3.3 million related to the 2014 and 2015 LTIP awards of restricted stock units. The Company expects the total expense associated with the portion of the Initial MIP Grant that vests if the $6.0 billion total enterprise value performance requirement is satisfied to be $22.1 million and the portion of the Initial MIP Grant that vests if the $6.6 billion total enterprise value performance requirement is satisfied to be $20.9 million, respectively. One-third of the Initial MIP Grants were paid in shares of the Company’s stock to members of its board of directors as well as its officers and other employees during the nine months ended September 30, 2017 and totaled $26.1 million (1,238,665 shares), of which a portion was capitalized in oil and gas properties and equipment as noted in the valuation and expense information above.

5.  INCOME TAXES:

The Company’s overall effective tax rate on pre-tax income was different than the statutory rate of 35% due primarily to valuation allowances.

The Company has recorded a valuation allowance against all deferred tax assets as of September 30, 2017.  Some or all of this valuation allowance may be reversed in future periods against future income. A tax benefit and corresponding tax receivable of approximately $6.9 million has been recorded for the quarter ended September 30, 2017 related to expected U.S. cash tax refunds.

The reorganization of the Company is considered to have resulted in a change of control for U.S. Income Tax purposes under IRC Section 382. However, pursuant to the special rules under IRC Section 382(h), the Company’s U.S. tax attributes, including its Net Operating Loss (NOL), is not expected to be subject to significant limitations due to the change of control.

6.  DERIVATIVE FINANCIAL INSTRUMENTS:

Objectives and Strategy:  The Company’s major market risk exposure is in the pricing applicable to its natural gas and oil production. Realized pricing is currently driven primarily by the prevailing price for the Company’s natural gas production. Historically, prices received for natural gas production have been volatile and unpredictable. Pricing volatility is expected to continue.  The prices we receive for our production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index price.  

The Company relies on various types of derivative instruments to manage its exposure to commodity price risk and to provide a level of certainty in the Company’s forward cash flows supporting the Company’s capital investment program.  These types of instruments may include fixed price swaps, costless collars, or basis differential swaps.  These contracts are financial instruments, and do not require or allow for physical delivery of the hedged commodity.  While mitigating the effects of fluctuating commodity prices, these derivative contracts may limit the benefits we would receive from increases in commodity prices above the fixed hedge prices.

The Company’s hedging policy limits the volumes hedged to not be greater than 50% of its forecasted production volumes without Board approval.

Fair Value of Commodity Derivatives:  FASB ASC 815 requires that all derivatives be recognized on the Consolidated Balance Sheets as either an asset or liability and be measured at fair value. Changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met.  The Company does not apply hedge accounting to any of its derivative instruments.

Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at fair value on the Consolidated Balance Sheets and the associated unrealized gains and losses are recorded as current income or expense in the Consolidated Statements of Operations. Unrealized gains or losses on commodity derivatives represent the non-cash change in the fair value of these derivative instruments and do not impact operating cash flows on the cash flow statement.

Commodity Derivative Contracts:  At September 30, 2017, the Company had the following open commodity derivative contracts to manage commodity price risks.  For the fixed price swaps, the Company receives the fixed price for the contract and

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

pays the variable price to the counterparty.  For the collars, the Company pays the counterparty if the market price is above the ceiling price and the counterparty pays the Company if the market price is below the floor on a notional quantity. The reference prices of these commodity derivative contracts are typically referenced to index prices as published by independent third parties.

Natural Gas:

 

 

 

The following table summarizes the pre-tax realized and unrealized gain (loss) the Company recognized related to its derivative instruments in the Consolidated Statements of Operations for the periods ended September 30, 2017 and 2016:

 

 

The realized gain or loss on commodity derivatives relates to actual amounts received or paid or to be received or paid under the Company’s derivative contracts and the unrealized gain or loss on commodity derivatives represents the change in the fair value of these derivative instruments over the remaining term of the contract.

7.  FAIR VALUE MEASUREMENTS:

As required by FASB ASC 820, the Company defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date and establishes a three-level hierarchy for measuring fair value. Fair value measurements are classified and disclosed in one of the following categories:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

 

 

Fair Value of Financial Instruments

The estimated fair value of financial instruments is the estimated amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported in the Consolidated Balance Sheets for cash and cash equivalents, restricted cash, accounts receivable, and accounts payable approximate fair value due to the immediate or short-term maturity of these financial instruments. The Company uses available market data and valuation methodologies to estimate the fair value of its debt. The valuation assumptions utilized to measure the fair value of the Company’s debt are considered Level 2 inputs.  This disclosure is presented in accordance with FASB ASC Topic 825, Financial Instruments, and does not impact the Company’s financial position, results of operations or cash flows.

 

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

8.  COMMITMENTS AND CONTINGENCIES:

The Plan provides for the treatment of claims against our bankruptcy estates, including claims for prepetition liabilities that have not otherwise been satisfied or addressed before we emerged from chapter 11 proceedings. As noted in this Quarterly Report on Form 10-Q, the claims resolution process associated with our chapter 11 proceedings is on-going, and we expect it to continue for an indefinite period of time.

Pending Claims – Ultra Resources Indebtedness

Our chapter 11 filings constituted events of default under Ultra Resources’ prepetition debt agreements. During our bankruptcy proceedings, many holders of this indebtedness filed proofs of claim with the Bankruptcy Court, asserting claims for the outstanding balance of the indebtedness, unpaid prepetition interest dates, unpaid postpetition interest (including interest at the default rates under the debt agreements), make-whole amounts, and other fees and obligations allegedly arising under the debt agreements. As previously disclosed, in connection with our emergence from bankruptcy and in accordance with the Plan, all of our obligations with respect to the Ultra Resources prepetition indebtedness and the associated debt agreements were cancelled, except to the limited extent expressly set forth in the Plan, and the holders of claims related to the indebtedness received payment in full of allowed claims (including with respect to outstanding principal, unpaid prepetition interest, and certain other prepetition fees and obligations arising under the debt agreements). In connection with confirmation and consummation of the Plan we entered into a stipulation with the claimants pursuant to which we agreed to establish and fund a $400.0 million reserve account after the Effective Date, pending resolution of make-whole and postpetition interest claims. On April 14, 2017, we funded the account. Following our emergence from bankruptcy, we continued to dispute the claims made by holders of the Ultra Resources’ indebtedness for certain make-whole amounts and postpetition interest at the default rates provided for in the debt agreements.

As previously disclosed in a Current Report on Form 8-K filed with the SEC on September 22, 2017, the Bankruptcy Court denied the Company’s objection to the pending make-whole and postpetition interest claims.  On October 6, 2017, the Bankruptcy Court entered an order requiring the Company to distribute amounts attributable to the disputed claims to the applicable parties.  As ordered on October 12, 2017, substantially all of the moneys held in the Reserve Fund, totaling $400.3 million were distributed.  In total, $399.0 million was distributed to the parties asserting the make-whole and post-petition interest claims and $1.3 million (the balance remaining after distributions to the parties asserting claims) was returned to the Company, see Note 9 for additional details.  During the quarter, the Company recorded a liability for $399.0 million, which is comprised of $223.8 million included in accrued liabilities and $175.2 million included in interest payable in the Consolidated Balance Sheets. The $223.8 million represents the fees owed under the make-whole claims described above, which are included in reorganization items in the Consolidated Statements of Operations and the $175.2 million represents postpetition interest at the default rate as described above, which is included in interest expense in the Consolidated Statement of Operations.  The Company has appealed the court order denying its objections to these claims, but it is not possible to determine the ultimate disposition of these matters at this time.

Royalties

On April 19, 2016, we received a preliminary determination notice from the Office of Natural Resources Revenue (“ONRR”) asserting that our allocation of certain processing costs and plant fuel use at certain processing plants were impermissibly charged as deductions in the determination of royalties owed under Federal oil and gas leases.  We dispute the preliminary determination and raised, with ONRR, several matters we believed may not have been considered in the preliminary determination notice.  ONRR filed a proof of claim in our bankruptcy proceedings asserting approximately $35.1 million in claims attributable to these royalty calculations. This claim and the preliminary determination notice could ultimately result in us being ordered to pay additional royalty to ONRR for prior, current and future periods.  We are not able to determine the likelihood or range of any additional royalties or, if and when assessed, whether such amounts would be material.

Oil Sales Contract

On April 29, 2016, we received a letter from counsel to Sunoco Partners Marketing & Terminals L.P. (“SPMT”) asserting that (1) we had breached, by anticipatory repudiation, a contract for the purchase and sale of crude oil between Ultra Resources and SPMT and (2) the contract was terminated. In the letter, SPMT demanded payment for damages resulting from the breach in the amount of $38.6 million. On August 31, 2016, SPMT filed a proof of claim with the Bankruptcy Court for $16.9 million. On December 13, 2016, we filed an objection to SPMT’s proof of claim, and on December 14, 2016, we filed an adversary

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proceeding against SPMT related to its breach of the contract during the prepetition period (as amended, the “Sunoco Adversary”).  In its April 25, 2017 reply to the Sunoco Adversary complaint, Sunoco asserted a counterclaim for matters addressed in its proof of claim.  Litigation related to this matter is proceeding in the Bankruptcy Court. At this time, we are not able to determine the likelihood or range of damages owed to SPMT, if any, related to this matter, or, if and when such amounts are assessed, whether such amounts would be material. We anticipate SPMT’s claims will be resolved in connection with our chapter 11 proceedings.

Other Claims

The Company is party to lawsuits related to disputes with respect to overriding royalty and other interests in certain of our operated leases in Pinedale, Wyoming. At this time, no determination of the outcome of these claims can be made, or, if such claims are determined, whether any amounts related to these matters would be material. We are defending these cases vigorously, and we expect these claims to be resolved by the Bankruptcy Court. The Company is also currently involved in various routine disputes and allegations incidental to its business operations. While it is not possible to determine the ultimate disposition of these matters, the Company believes that the resolution of all such pending or threatened litigation is not likely to have a material adverse effect on the Company’s financial position or results of operations.

9.  SUBSEQUENT EVENTS:

The Company has evaluated the period subsequent to September 30, 2017 for events that did not exist at the balance sheet date but arose after that date and determined that no subsequent events arose that should be disclosed in order to keep the financial statements from being misleading, except as set forth below.

As previously disclosed in a Current Report on Form 8-K filed with the SEC on September 22, 2017, the Bankruptcy Court denied the Company’s objection to the pending make-whole and postpetition interest claims that remained following emergence from chapter 11 proceedings.  On October 6, 2017, the Bankruptcy Court ordered that the amount held in the Reserve Fund be distributed to the respective holders of prepetition indebtedness, based on their applicable claims.  On October 12, 2017, the Company released the $400.3 million out of the Reserve Fund.  On October 13, 2017, the funds were distributed according to the Bankruptcy Court’s October 6, 2017 order.  Undistributed funds of $1.3 million were returned to the Company, which was in accordance with the Distribution Notice filed with the Bankruptcy Court.  See Note 8 for additional details.

 

 

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ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion of the financial condition and operating results of the Company should be read in conjunction with the Company’s consolidated financial statements and related notes. Except as otherwise indicated, all amounts are expressed in U.S. dollars.

Overview

Ultra Petroleum Corp. (the “Company”) is an independent exploration and production company focused on developing its long-life natural gas reserves in the Green River Basin of Wyoming - the Pinedale and Jonah fields, its oil reserves in the Uinta Basin in Utah and its natural gas reserves in the Appalachian Basin of Pennsylvania. The Company operates in one industry segment, natural gas and oil exploration and development, within one geographical segment, the United States.

The Company currently conducts operations exclusively in the United States. Substantially all of its oil and natural gas activities are conducted jointly with others and, accordingly, amounts presented reflect only the Company’s proportionate interest in such activities. The Company continues to focus on improving its drilling and production results through gaining efficiencies with the use of advanced technologies, detailed technical analysis of its properties and leveraging its experience into improved operational efficiencies.  Inflation has not had, nor is it expected to have in the foreseeable future, a material impact on the Company’s results of operations.

The Company currently generates its revenue, earnings and cash flow primarily from the production and sales of natural gas and condensate from its properties in southwest Wyoming with a portion of the Company’s revenues coming from oil sales from its properties in the Uinta Basin in Utah and gas sales from wells located in the Appalachian Basin in Pennsylvania.

The prices of oil and natural gas are critical factors to the Company’s business. The prices of oil and natural gas have historically been volatile, and this volatility could be detrimental to the Company’s financial performance.  As a result, and from time to time, the Company tries to limit the impact of this volatility on its results by entering into swap agreements and/or fixed price forward physical delivery contracts for natural gas and oil. See Note 6 for additional details.

During the quarter ended September 30, 2017, the average price realization for the Company’s natural gas was $2.87 per Mcf, including realized gains and losses on commodity derivatives compared with $2.62 per Mcf during the quarter ended September 30, 2016.  The Company’s average price realization for natural gas was $2.74 per Mcf, excluding the realized gains and losses on commodity derivatives.  This compares with $2.62 per Mcf during the quarter ended September 30, 2016.

During the quarter ended September 30, 2017, the average price realization for the Company’s oil was $45.86 per barrel compared to $41.55 per barrel for the quarter ended September 30, 2016.

Chapter 11 Proceedings

Voluntary Reorganization Under Chapter 11

On April 29, 2016 (the “Petition Date”), the Company and its subsidiaries (collectively, the “Debtors”) filed voluntary petitions under chapter 11 of title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). Our chapter 11 cases were jointly administered under the caption In re Ultra Petroleum Corp., et al, Case No. 16-32202 (MI) (Bankr. S.D. Tex.).

On February 13, 2017, the Bankruptcy Court approved our amended Disclosure Statement (by order subsequently amended on February 21, 2017), on March 14, 2017, the Bankruptcy Court confirmed our Debtors’ Second Amended Joint Chapter 11 Plan of Reorganization (the “Plan”), and on April 12, 2017 (the “Effective Date”), we emerged from bankruptcy.

As a result of our improved financial condition and successful emergence from chapter 11, we believe we now have sufficient liquidity to fund our future cash requirements for operations, capital expenditures and working capital purposes. As a result, substantial doubt no longer exists regarding the Company’s ability to meet its obligations as they become due within one year after the date that the financial statements are issued.  

Because we emerged from bankruptcy during the nine months ended September 30, 2017 and because we continue our work to reconcile, resolve and pay certain prepetition claims asserted against us during our chapter 11 cases, certain aspects of our chapter 11 cases are described below to provide context to our financial condition and results of operations for the period

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presented in this Quarterly Report on Form 10-Q.  Information about our chapter 11 cases is available at a website maintained by our claims agent, Epiq Systems (http://dm.epiq11.com/UPT/Docket).

In addition, because our operations and ability to execute our business remain subject to various risks and uncertainties, including risks and uncertainties related to our chapter 11 cases, readers are encouraged to review and consider the items described in Item 1A, “Risk Factors” in our Annual Report on Form 10-K for our fiscal year ended December 31, 2016 and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2017.

Plan Support Agreement, Rights Offering, Backstop Commitment Agreement and Exit Financing Commitment Letter

As previously disclosed:

Fresh Start Accounting

As previously disclosed, we are not required to apply fresh start accounting to our financial statements in connection with our emergence from bankruptcy because the reorganization value of our assets immediately prior to confirmation of the Plan exceeded our aggregate postpetition liabilities and allowed claims.

Liabilities Subject to Compromise

The following table reconciles the settlement of liabilities subject to compromise included in our Consolidated Balance Sheets from December 31, 2016 through the nine months ended September 30, 2017:

 

 

Bankruptcy Claims Resolution Process

The claims filed against us during our chapter 11 proceedings are voluminous. In addition, claimants may file amended or modified claims in the future, which modifications or amendments may be material. The claims resolution process is on-going,

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and the ultimate number and amount of prepetition claims is not presently known, nor can the ultimate recovery with respect to allowed claims be presently ascertained.

As a part of the claims resolution process, we are working to resolve differences between amounts we listed in information filed during our bankruptcy proceedings and the amounts of claims filed by our creditors. We have filed, and we will continue to file, objections with the Bankruptcy Court as necessary with respect to claims we believe should be disallowed.

Costs of Reorganization

We have incurred significant costs associated with our reorganization and the chapter 11 proceedings. We expect these costs, which are being expensed as incurred, have affected and may continue to significantly affect our results of operations. For additional information about the costs of our reorganization and chapter 11 proceedings, see “Reorganization items, net” below.

The following table summarizes the components included in Reorganization items, net in our Consolidated Statements of Operations for the nine months ended September 30, 2017 and 2016:

 

 

Critical Accounting Policies

The discussion and analysis of the Company’s financial condition and results of operations is based upon consolidated financial statements, which have been prepared in accordance with U.S. Generally Accepted Accounting Principles (“GAAP”). In addition, application of GAAP requires the use of estimates, judgments and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements as well as the revenues and expenses reported during the period. Changes in these estimates related to judgments and assumptions will occur as a result of future events, and, accordingly, actual results could differ from amounts estimated. Set forth below is a discussion of the critical accounting policies used in the preparation of our financial statements which we believe involve the most complex or subjective decisions or assessments.

Derivative Instruments and Hedging Activities.  The Company follows Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 815, Derivatives and Hedging (“FASB ASC 815”).  The Company records the fair value of its commodity derivatives as an asset or liability on the Consolidated Balance Sheets, and records the changes in the fair value of its commodity derivatives in the Consolidated Statements of Operations.

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Fair Value Measurements.  The Company follows FASB ASC Topic 820, Fair Value Measurements and Disclosures (“FASB ASC 820”). Under FASB ASC 820, fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at measurement date and establishes a three-level hierarchy for measuring fair value.

 

 

 

Asset Retirement Obligation.  The Company’s asset retirement obligations (“ARO”) consist primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with its oil and natural gas properties. FASB ASC Topic 410, Asset Retirement and Environmental Obligations (“FASB ASC 410”) requires that the fair value of a liability for an ARO be recognized in the period in which it is incurred with the associated asset retirement cost capitalized as part of the carrying cost of the oil and natural gas asset. The recognition of an ARO requires that management make numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO, amounts and timing of settlements, the credit-adjusted, risk-free rate to be used, inflation rates, and future advances in technology. In periods subsequent to initial measurement of the ARO, the Company must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to the passage of time impact net income as accretion expense. The related capitalized costs, including revisions thereto, are charged to expense through depletion, depreciation and amortization (“DD&A”).  As a full cost company, settlements for asset retirement obligations for abandonment are adjusted to the full cost pool.  The asset retirement obligation is included within other long-term obligations in the accompanying Consolidated Balance Sheets.

Share-Based Payment Arrangements.  The Company applies FASB ASC Topic 718, Compensation – Stock Compensation (“FASB ASC 718”), which requires the measurement and recognition of compensation expense for all share-based payment awards made to employees and directors, including employee stock options, based on estimated fair values. Share-based compensation expense recognized for the nine months ended September 30, 2017 and 2016 was $34.2 million and $4.0 million, respectively. See Note 4 for additional details.

Property, Plant and Equipment.  Capital assets are recorded at cost and depreciated using the declining-balance method based on their respective useful life.

Full Cost Method of Accounting.  The Company uses the full cost method of accounting for oil and gas exploration and development activities as defined by the Securities and Exchange Commission (“SEC”) Release No. 33-8995, Modernization of Oil and Gas Reporting Requirements (“SEC Release No. 33-8995”) and FASB ASC Topic 932, Extractive Activities – Oil and Gas (“FASB ASC 932”). Under the full cost method of accounting, all costs associated with the exploration for and development of oil and gas reserves are capitalized on a country-by-country basis. Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling both productive and non-productive wells and overhead charges directly related to acquisition, exploration and development activities. Substantially all of the oil and gas activities are conducted jointly with others and, accordingly, the amounts reflect only the Company’s proportionate interest in such activities.

Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed quarterly, on a country-by-country basis, utilizing the average of prices in effect on the first day of the month for the preceding twelve-month period in accordance with SEC Release No. 33-8995. The ceiling limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved crude oil and

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natural gas reserves discounted at 10% plus the lower of cost or market value of unproved properties less any associated tax effects. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and results in a lower DD&A rate in future periods. A write-down may not be reversed in future periods even though higher oil and natural gas prices may subsequently increase the ceiling.

The calculation of the ceiling test is based upon estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves, in projecting the future rates of production and in the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. The Company did not have any write-downs related to the full cost ceiling limitation during the nine months ended September 30, 2017 or 2016.  

Revenue Recognition.  The Company generally sells oil and natural gas under both long-term and short-term agreements at prevailing market prices. The Company recognizes revenues when the oil and natural gas is delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectability is reasonably assured. The Company accounts for oil and natural gas sales using the “entitlements method.” Under the entitlements method, revenue is recorded based upon the Company’s ownership share of volumes sold, regardless of whether it has taken its ownership share of such volumes.

Make-up provisions and ultimate settlements of volume imbalances are generally governed by agreements between the Company and its partners with respect to specific properties or, in the absence of such agreements, through negotiation. The value of volumes over- or under-produced can change based on changes in commodity prices. The Company prefers the entitlements method of accounting for oil and natural gas sales because it allows for recognition of revenue based on its actual share of jointly owned production, results in better matching of revenue with related operating expenses, and provides balance sheet recognition of the estimated value of product imbalance.  The Company’s imbalance obligations as of September 30, 2017 and December 31, 2016 were immaterial.

Valuation of Deferred Tax Assets.  The Company uses the asset and liability method of accounting for income taxes. Under this method, future income tax assets and liabilities are determined based on differences between the financial statement carrying values and their respective income tax basis (temporary differences).

To assess the realization of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment.

The Company has recorded a valuation allowance against all of its deferred tax assets as of September 30, 2017.  Some or all of this valuation allowance may be reversed in future periods against future income.

The reorganization of the Company is considered to have resulted in a change of control for U.S. Income Tax purposes under IRC Section 382. However, pursuant to the special rules under IRC Section 382(h), the Company’s U.S. tax attributes, including its Net Operating Loss (NOL), is not expected to be subject to significant limitations due to the change of control.

Deferred Financing Costs.  The Company follows ASU No. 2015-3, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs and includes the costs for issuing debt, including issuance discounts, except those related to the revolving credit facility, as a direct deduction from the carrying amount of the related debt liability. Costs related to the issuance of the revolving credit facility are recorded as an asset in the Consolidated Balance Sheets.

Deposits and Retainers. Deposits and retainers primarily consists of payments related to surety bonds as of December 31, 2016.

Conversion of Barrels of Oil to Mcfe of Gas.  The Company converts Bbls of oil and other liquid hydrocarbons to Mcfe at a ratio of one Bbl of oil or liquids to six Mcfe.  This conversion ratio, which is typically used in the oil and gas industry, represents the approximate energy equivalent of a barrel of oil or other liquids to an Mcf of natural gas.  The sales price of one Bbl of oil or liquids has been much higher than the sales price of six Mcf of natural gas over the last several years, so a six to one conversion ratio does not represent the economic equivalency of six Mcf of natural gas to a Bbl of oil or other liquids.

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Recent accounting pronouncements:

Statement of Cash Flows.  In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (“ASU No. 2016-18”). The guidance requires that an explanation is included in the cash flow statement of the change in the total of (1) cash, (2) cash equivalents, and (3) restricted cash or restricted cash equivalents. ASU No. 2016-18 also clarifies that transfers between cash, cash equivalents and restricted cash or restricted cash equivalents should not be reported as cash flow activities and requires the nature of the restrictions on cash, cash equivalents, and restricted cash or restricted cash equivalents to be disclosed. For public companies, the standard will take effect for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017 with earlier application permitted. The Company is still evaluating the impact of ASU No. 2016-18 on its consolidated financial statements.

Statement of Cash Flows.  In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230) (“ASU No. 2016-15”). The guidance requires that debt prepayment or debt extinguishment costs, including third-party costs, premiums paid, and other fees paid to lenders, be classified as cash outflows for financing activities. For public companies, the standard will take effect for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017 with earlier application permitted. The Company does not expect the adoption of ASU No. 2016-15 to have a material impact on its consolidated financial statements.

Leases.  In February 2016, the FASB issued ASU 2016-02, Leases (“ASU No. 2016-02”).  The guidance requires that lessees will be required to recognize assets and liabilities on the balance sheet for the rights and obligations created by all leases with terms of more than 12 months. The ASU will also require disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. These disclosures include qualitative and quantitative information. For public companies, the standard will take effect for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018 with earlier application permitted. The Company is still evaluating the impact of ASU No. 2016-02 on its consolidated financial statements.

Stock Compensation.  In May 2017, the FASB issued ASU 2017-09, Compensation-Stock Compensation (Topic 718) (“ASU No. 2017-09”), which is intended to clarify and reduce diversity in practice and cost and complexity when applying the guidance in Topic 718, Compensation-Stock Compensation, to a change to the terms or conditions of a share-based payment award.  For public companies, the standard will take effect for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017 with earlier application permitted.  The Company does not expect the adoption of ASU No. 2017-09 to have a material impact on its consolidated financial statements

Revenue from Contracts with Customers.  In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) and in 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), and ASU 2016-10, Revenues from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing, which supersede the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities-Oil and Gas-Revenue Recognition. The new standard requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services.

We are currently evaluating the provisions of ASU 2014-09 and assessing the impact, if any, it may have on our financial position and results of operations. As part of our assessment work to date, we have completed training of the new ASU’s revenue recognition model, dedicated resources to its implementation, and initiated contract review and documentation; including analyzing the standard’s impact on our contract portfolio, comparing historical accounting policies and practices to the requirements of the new standard, and identifying differences from applying the requirements of the new standards to our contracts.  We are evaluating the expanded disclosure requirements under the new standard and are also reviewing our processes, systems, and internal controls over financial reporting to ensure the appropriate information will be available for these disclosures.  While we are continuing to assess all potential impacts of the standard, we currently believe the most significant impacts relate to principal versus agent considerations and the use of the entitlements method for oil and natural gas sales, both of which are continuing to be evaluated by the Company.

The Company is required to adopt the new standards in the first quarter of 2018 using one of two application methods: retrospectively to each prior reporting period presented (full retrospective method), or retrospectively with the cumulative effect of initially applying the guidance recognized at the date of initial application (the modified retrospective method). The Company currently anticipates adopting the standard using the modified retrospective method.

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RESULTS OF OPERATIONS:

 

 

Quarter Ended September 30, 2017 vs. Quarter Ended September 30, 2016

Production, Commodity Derivatives and Revenues:

Production.  During the quarter ended September 30, 2017, total production increased on a gas equivalent basis to 71.1 Bcfe compared to 69.3 Bcfe for the same quarter in 2016. The increase is primarily attributable to increased capital investments during the nine months ended September 30, 2017.

Commodity Prices – Natural Gas.  Realized natural gas prices, including realized gains and losses on commodity derivatives, increased 10% to $2.87 per Mcf in the third quarter of 2017 as compared to $2.62 per Mcf for the same quarter of 2016.  During the three months ended September 30, 2017, the Company’s average price for natural gas was $2.74 per Mcf as compared to $2.62 per Mcf for the same period in 2016.

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Commodity Prices – Oil.  During the quarter ended September 30, 2017, the average price realization for the Company’s oil was $45.86 per barrel compared to $41.55 per barrel for the same period in 2016. The Company does not currently have any open derivative contracts related to oil prices.

Revenues.  The increase in average oil and natural gas prices and the increase in total production resulted in revenues increasing to $217.6 million for the quarter ended September 30, 2017 as compared to $199.3 million for the same period in 2016.

Operating Costs and Expenses:

Lease Operating Expense.  Lease operating expense (“LOE”) increased to $23.1 million during the third quarter of 2017 compared to $19.9 million during the same period in 2016 primarily related to the increase in producing well counts. On a unit of production basis, LOE costs increased to $0.33 per Mcfe during the third quarter of 2017 compared with $0.29 per Mcfe during the third quarter of 2016.

Facility Lease Expense.  During December 2012, the Company sold a system of liquids gathering pipelines and central gathering facilities (the “LGS”) and certain associated real property rights in the Pinedale Anticline in Wyoming. The Company entered into a long-term, triple net lease agreement with the buyer relating to the use of the LGS (the “Lease Agreement”). The Lease Agreement provides for an initial term of 15 years, and annual rent of $20.0 million during the initial term (as adjusted annually for changes based on the consumer price index) that may increase if certain volume thresholds are exceeded. The lease is classified as an operating lease. For the three months ended September 30, 2017, the Company recognized operating lease expense associated with the Lease Agreement of $5.3 million, or $0.07 per Mcfe, as compared to $5.2 million, or $0.07 per Mcfe for the same period in 2016.

Production Taxes.  During the three months ended September 30, 2017, production taxes increased to $22.5 million compared to $20.7 million during the same period in 2016, or $0.32 per Mcfe compared to $0.30 per Mcfe, respectively. Production taxes are primarily calculated based on a percentage of revenue from production in Wyoming and Utah after certain deductions and were 10.3% of revenues for the quarter ended September 30, 2017 and 10.4% of revenues for the same period in 2016.  The increase in per unit taxes is primarily attributable to increased oil and natural gas prices during the quarter ended September 30, 2017 as compared to the same period in 2016.

Gathering Fees.  Gathering fees increased to $22.2 million for the three months ended September 30, 2017 compared to $21.2 million during the same period in 2016 largely related to increased production.  On a per unit basis, gathering fees remained flat at $0.31 per Mcfe for the three months ended September 30, 2017 and 2016.

Transportation Charges.  As a result of termination of the Rockies Express Pipeline (“Rockies Express”) contract during the first quarter of 2016, there were no transportation charges for the quarter ended September 30, 2017 or 2016.

Depletion, Depreciation and Amortization.  DD&A expense of $41.1 million during the three months ended September 30, 2017 increased compared to $31.2 million for the same period in 2016, primarily attributable to the recognition of proved undeveloped properties (PUDs) as a result of emergence from chapter 11 proceedings.  On a unit of production basis, the DD&A rate increased to $0.58 per Mcfe for the quarter ended September 30, 2017 compared to $0.45 per Mcfe for the quarter ended September 30, 2016.

General and Administrative Expenses. General and administrative expenses increased to $8.2 million for the quarter ended September 30, 2017 compared to $1.6 million for the same period in 2016 primarily attributable to $7.9 million of non-cash stock incentive compensation expense that was incurred as part of the 2017 Stock Incentive Plan, see Note 4 for additional details.  On a per unit basis, general and administrative expenses increased to $0.12 per Mcfe for the quarter ended September 30, 2017 compared to $0.02 per Mcfe for the quarter ended September 30, 2016.

Other Income and Expenses:

Interest Expense.  During the quarter ended September 30, 2017, interest expense of $210.1 million was recognized which is comprised $34.9 million of interest incurred on the Revolving Credit Facility, the Term Loan Facility, and the Notes (see Note 3 for additional details) and $175.2 million for postpetition interest, related to the Bankruptcy Court order denying our objection to postpetition interest claims, at the default rate for the period beginning April 29, 2016 through April 12, 2017, as described in Note 8.  There was no interest expense recognized during the three months ended September 30, 2016 as the Company did not recognize any interest expense subsequent to the Petition Date and while in chapter 11.

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Deferred Gain on Sale of Liquids Gathering System.  During the quarters ended September 30, 2017 and 2016, the Company recognized $2.6 million in deferred gain on sale of the liquids gathering system relating to the sale of a system of pipelines and central gathering facilities and certain associated real property rights in the Pinedale Anticline in Wyoming during December 2012.

Commodity Derivatives:

Gain/(Loss) on Commodity Derivatives. During the quarter ended September 30, 2017, the Company recognized a gain of $4.7 million related to commodity derivatives. There were no open derivative contracts for the same period in 2016. Of this total, the Company recognized $8.9 million related to realized gain on commodity derivatives. The realized gain or loss on commodity derivatives relates to actual amounts received or paid under the Company’s derivative contracts. This gain or loss on commodity derivatives also includes a $4.2 million unrealized loss on commodity derivatives at September 30, 2017. The unrealized gain or loss on commodity derivatives represents the non-cash charge attributable to the change in the fair value of these derivative instruments over the remaining term of the contract.  See Note 6 for additional details.

Reorganization Items:

Reorganization Items, Net. Reorganization items, net increased with expense of $227.1 million for the quarter ended September 30, 2017 compared to $3.1 million during the same period in 2016.  The expense represents $3.3 million of professional fees incurred related to the Company’s chapter 11 proceedings and $223.8 million related to the Bankruptcy Court order denying our objection to the make-whole claims as further described in Note 8.

Income (Loss) from Continuing Operations:

Pretax Income (Loss).  The Company recognized a loss before income taxes of $334.6 million for the quarter ended September 30, 2017 compared with income before income taxes of $98.5 million for the same period in 2016. The decrease in earnings is attributable to an increase in interest expense, DD&A, reorganization items related to the Bankruptcy Court order denying our objection to the make-whole claims, and general and administrative expense, partially offset by an increase in revenues due to an increase in average oil and natural gas prices and production during the three months ended September 30, 2017.

Income Taxes.  The Company recorded a $6.9 million tax benefit for the three months ended September 30, 2017 related to expected U.S. cash tax refunds.  The Company has recorded a valuation allowance against all deferred tax assets as of September 30, 2017.  Some or all of this valuation allowance may be reversed in future periods against future income.

Net Income (Loss).  For the three months ended September 30, 2017, the Company recognized a net loss of $327.7 million, or $(1.67) per diluted share, as compared with net income of $98.4 million or $1.22 per diluted share, for the same period in 2016. The decrease in earnings is attributable an increase in interest expense, DD&A, reorganization items related to the Bankruptcy Court order denying our objection to the make-whole claims, and general and administrative expense, partially offset by an increase in revenues due to an increase in average oil and natural gas prices and production during the three months ended September 30, 2017.

Nine Months Ended September 30, 2017 vs. Nine Months Ended September 30, 2016

Production, Commodity Derivatives and Revenues:

Production.  During the nine months ended September 30, 2017, total production decreased by 5% on a gas equivalent basis to 202.2 Bcfe compared to 213.5 Bcfe for the same period in 2016 primarily as a result of decreased capital investment during 2016.

Commodity Prices – Natural Gas.  Realized natural gas prices, including realized gains and losses on commodity derivatives, increased 38% to $2.95 per Mcf during the nine months ended September 30, 2017 as compared to $2.13 per Mcf for the same period in 2016.  During the nine months ended September 30, 2017, the Company entered into additional natural gas price commodity derivative contracts, see Note 6 for additional details. During the nine months ended September 30, 2017, the Company’s average price for natural gas excluding realized gains and losses on commodity derivatives was $2.91 per Mcf as compared to $2.13 per Mcf for the same period in 2016.

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Commodity Prices – Oil.  During the nine months ended September 30, 2017, the average price realization for the Company’s oil was $46.21 per barrel compared with $35.98 per barrel during the same period in 2016.  The Company does not currently have any open derivative contracts related to oil prices.  

Revenues.  The increase in average oil and natural gas prices, partially offset by the decrease in total production, resulted in revenues increasing to $651.2 million for the nine months ended September 30, 2017 as compared to $505.2 million for the same period in 2016.

Operating Costs and Expenses:

Lease Operating Expense.  LOE increased to $69.4 million during the nine months ended September 30, 2017 compared to $67.2 million during the same period in 2016 primarily related to the increase in producing well counts. On a unit of production basis, LOE costs increased to $0.34 per Mcfe during the nine months ended September 30, 2017 compared to $0.31 per Mcfe during the same period in 2016.

Facility Lease Expense.  During December 2012, the Company sold the LGS and certain associated real property rights in the Pinedale Anticline in Wyoming and the Company entered into the Lease Agreement. The Lease Agreement provides for an initial term of 15 years, and annual rent of $20.0 million during the initial term (as adjusted annually for changes based on the consumer price index) and may increase if certain volume thresholds are exceeded. For the nine months ended September 30, 2017, the Company recognized operating lease expense associated with the Lease Agreement of $15.7 million, or $0.08 per Mcfe, as compared to $15.5 million, or $0.07 per Mcfe, for the same period in 2016.

Production Taxes.  During the nine months ended September 30, 2017, production taxes were $66.4 million compared to $49.4 million during the same period in 2016, or $0.33 per Mcfe compared to $0.23 per Mcfe. Production taxes are primarily calculated based on a percentage of revenue from production in Wyoming and Utah after certain deductions and were 10.2% of revenues for the nine months ended September 30, 2017 and 9.8% of revenues for the same period in 2016.  The increase in per unit taxes is primarily attributable to increased oil and natural gas prices during the nine months ended September 30, 2017 as compared to the same period in 2016.

Gathering Fees.  Gathering fees decreased slightly to $63.8 million for the nine months ended September 30, 2017 compared to $65.1 million during the same period in 2016.  On a per unit basis, gathering fees increased at $0.32 per Mcfe for the nine months ended September 30, 2017 compared to $0.30 per Mcfe for the same period in 2016.

Transportation Charges.  As a result of the termination of the Rockies Express Pipeline (“Rockies Express”) contract during the first quarter of 2016, there were no transportation charges for the nine months ended September 30, 2017. Transportation charges were $23.8 million for the same period in 2016.

Depletion, Depreciation and Amortization.  DD&A expenses increased to $111.5 million during the nine months ended September 30, 2017 from $93.3 million for the same period in 2016, primarily attributable to the recognition of proved undeveloped properties (PUDs) as a result of emergence from chapter 11 proceedings. On a unit of production basis, the DD&A rate increased to $0.55 per Mcfe for the nine months ended September 30, 2017 compared to $0.44 per Mcfe for the nine months ended September 30, 2016.

General and Administrative Expenses. General and administrative expenses increased to $34.3 million for the nine months ended September 30, 2017 compared to $7.2 million for the same period in 2016. The increase in general and administrative expenses is primarily attributable to the $34.2 million of non-cash stock incentive compensation expense that was incurred as part of the 2017 Stock Incentive Plan, see Note 4 for additional details. On a per unit basis, general and administrative expenses increased to $0.17 per Mcfe for the nine months ended September 30, 2017 compared to $0.03 per Mcfe for the nine months ended September 30, 2016.

Other Income and Expenses:

Interest Expense.  Interest expense increased to $325.0 million during the nine months ended September 30, 2017 compared to $66.6 million during the same period in 2016. The increase in interest expense represents accrued postpetition interest for the period beginning April 29, 2016 through April 12, 2017, interest expense incurred on the Revolving Credit Facility, the Term Loan Facility, and the Notes (see Note 3 for additional details), and postpetition interest, related to the Bankruptcy Court order denying our objection to postpetition interest claims, at the default rate for the period beginning April 29, 2016 through April 12, 2017, as described in Note 8.

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Restructuring Expenses. During the nine months ended September 30, 2016, the Company incurred $7.2 million in costs and fees in connection with its efforts to restructure its debt prior to filing the chapter 11 petitions.

Contract Settlement Expense.  As previously disclosed, during the nine months ended September 30, 2017, the Company incurred $52.7 million in expense primarily related to the Sempra Rockies Marketing, LLC (“Sempra”) settlement.  Sempra filed a claim in 2016 against the Company in regard to the violation of the capacity agreement.  The Company reached the settlement on April 10, 2017, the expense was accrued as of March 31, 2017, and was paid in full in May 2017.  There were no material contract settlement expenses for the same period in 2016.

Deferred Gain on Sale of Liquids Gathering System.  During the nine months ended September 30, 2017 and 2016, the Company recognized $7.9 million in deferred gain on sale of the liquids gathering system relating to the sale of a system of pipelines and central gathering facilities and certain associated real property rights in the Pinedale Anticline in Wyoming during December 2012.

Commodity Derivatives:

Gain (Loss) on Commodity Derivatives. During the nine months ended September 30, 2017, the Company recognized a gain of $12.1 million related to commodity derivatives. There were no open derivative contracts for the same period in 2016. Of this total, the Company recognized $8.0 million related to realized gain on commodity derivatives. The realized gain or loss on commodity derivatives relates to actual amounts received or paid under the Company’s derivative contracts. This gain or loss on commodity derivatives also includes a $4.1 million unrealized gain on commodity derivatives at September 30, 2017. The unrealized gain or loss on commodity derivatives represents the non-cash charge attributable to the change in the fair value of these derivative instruments over the remaining term of the contract.  See Note 6 for additional details.

Reorganization Items:

Reorganization Items, Net. Reorganization items, net increased to income of $142.1 million for the nine months ended September 30, 2017 compared to expense of $25.3 million for the same period 2016.  The increase is due to the emergence from chapter 11 proceedings during the nine months ended September 30, 2017 and is primarily comprised of expenses of $65.2 million in professional fees, settlements, and interest income associated with the Company’s chapter 11 cases and of $223.8 million related to the Bankruptcy Court order denying our objection to the make-whole claims offset by the gain of $431.1 million, which primarily represents the gain on the debt for equity exchange related to the 2018 and 2024 Senior Notes.  No cash tax is expected to be recognized as the result of this gain.

Income from Continuing Operations:

Pretax Income.  The Company recognized income before income taxes of $74.7 million for the nine months ended September 30, 2017 compared with income before income taxes of $90.3 million for the same period in 2016. The decrease in earnings is attributable to an increase in interest expense, DD&A, and general and administrative expense, partially offset by an increase in revenues due to an increase in average oil and natural gas prices and the net effect of reorganization items during the nine months ended September 30, 2017.

Income Taxes.  The Company recorded a $6.9 million tax benefit for the nine months ended September 30, 2017 related to expected U.S. cash tax refunds. The Company has recorded a valuation allowance against all deferred tax assets as of September 30, 2017.  Some or all of this valuation allowance may be reversed in future periods against future income.

Net Income.  For the nine months ended September 30, 2017, the Company recognized net income of $81.6 million, or $0.53 per diluted share, as compared with net income of $90.6 million, or $1.13 per diluted share, for the same period in 2016. The decrease in earnings is attributable to an increase in interest expense, DD&A, and general and administrative expense, partially offset by increased revenues due to increases in the average oil and natural gas prices and the net effect of reorganization items during the nine months ended September 30, 2017.

LIQUIDITY AND CAPITAL RESOURCES

During the nine months ended September 30, 2017, we funded our operations primarily through cash flows from operating activities and borrowings under the RBL Credit Agreement (defined below).  The Company plans to fund our operations for the remainder of its fiscal year 2017 primarily through cash on hand and cash flows from operating activities.  However, future cash flows are subject to a number of risks, and are highly dependent on the prices we receive for oil and natural gas.

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At September 30, 2017, the Company reported a cash position of $5.4 million. Working capital (deficit) was $(157.3) million compared to working capital of $308.6 million at September 30, 2016. At September 30, 2017, the Company had $20.0 million in outstanding borrowings and $405.0 million of available borrowing capacity under the RBL Credit Agreement (defined below).

Given the current level of volatility in the market and the unpredictability of certain costs that could potentially arise in our operations, the Company’s liquidity needs could be significantly higher than the Company currently anticipates.  The Company’s ability to maintain adequate liquidity depends on the prevailing market prices for oil and natural gas, the successful operation of the business, and appropriate management of operating expenses and capital spending.  The Company’s anticipated liquidity needs are highly sensitive to changes in each of these and other factors.  The Company’s positive cash provided by operating activities, along with availability under the RBL Credit Agreement (defined below), are projected to be sufficient to fund the Company’s budgeted capital investment program for 2017.

Capital Expenditures. For the nine month period ended September 30, 2017, total capital expenditures were $386.8 million. During this period, the Company participated in 157 gross (130.1 net) wells in Wyoming that were drilled to total depth and cased. No wells are scheduled to be drilled in Utah or Pennsylvania during 2017.

2017 Capital Investment Plan. For 2017, our capital expenditures are expected to be approximately $540.0 million. We expect to fund these capital expenditures through cash flows from operations, activities and borrowings under the RBL Credit Agreement (defined below), and cash on hand. We expect to allocate nearly all of the budget to development activities in our Pinedale field.

Common stock – NASDAQ Listing. In connection with its emergence from chapter 11, the Company issued 194,991,656 shares of its new common stock. All of the Company’s existing common stock that had been trading under the ticker symbol “UPLMQ” was cancelled and the existing stockholders received new common stock as set forth in the Plan. All of the allowed claims attributable to the prepetition high yield bonds issued by the Company were converted into new common stock as set forth in the Plan. The shares related to the $580.0 million equity rights offering were issued and the fee payable to the commitment parties under the Backstop Commitment Agreement was paid in new common stock as set forth in the Plan. The newly-issued common stock began trading on The NASDAQ Global Select Market on April 13, 2017 under the ticker symbol “UPL”.

Ultra Resources, Inc.

Credit Agreement. On April 12, 2017, Ultra Resources, Inc. (“Ultra Resources”), as the borrower, entered into a Credit Agreement with the Company and UP Energy Corporation, as parent guarantors, with Bank of Montreal, as administrative agent, and with the other lenders party thereto from time to time (as amended, the “RBL Credit Agreement”), providing for a revolving credit facility (the “Revolving Credit Facility”) for an aggregate amount of $400.0 million and an initial borrowing base of $1.2 billion (which limits the aggregate amount of first lien debt under the Revolving Credit Facility and the Term Loan Facility (defined below)).  As previously disclosed in a Current Report Form 8-K filed with the SEC on September 19, 2017, the Bank of Montreal, as administrative agent and the other lenders party thereto, approved an increase in the borrowing base under the RBL Credit Agreement from $1.2 billion to $1.4 billion as requested by the Company, which included an increase in the commitments under the RBL Credit Agreement to an aggregate amount of $425.0 million.  At September 30, 2017, Ultra Resources had $20.0 million in outstanding borrowings under the RBL Credit Agreement, total commitments under the RBL Credit Agreement of $425.0.0 million and a borrowing base of $1.4 billion.  There are no scheduled borrowing base redeterminations until April 1, 2018.

The Revolving Credit Facility has capacity for Ultra Resources to increase the commitments subject to certain conditions, and has $50.0 million of the commitments available for the issuance of letters of credit. The Revolving Credit Facility bears interest either at a rate equal to (a) a customary London interbank offered rate plus an applicable margin that varies from 250 to 350 basis points or (b) the base rate plus an applicable margin that varies from 150 to 250 basis points.  The interest rate remained the same for the Revolving Credit Facility subsequent to the approved commitments increased noted above.  The Revolving Credit Facility loans mature on January 12, 2022.

The RBL Credit Agreement requires Ultra Resources to maintain (i) an interest coverage ratio of 2.50 to 1.00; (ii) a current ratio, including the unused portion of the Revolving Credit Facility, of 1.00 to 1.00; (iii) a consolidated net leverage ratio of (A) 4.25 to 1.00 as of the last day of any fiscal quarter ending on or before December 31, 2017 and (B) 4.00 to 1.00, as of the last day of any fiscal quarter thereafter; and (iv) after the Company has obtained investment grade rating an asset coverage ratio of 1.50 to 1.00. At September 30, 2017, Ultra Resources was in compliance with all of its debt covenants under the RBL Credit Agreement.

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Ultra Resources is required to pay a commitment fee on the average daily unused portion of the Revolving Credit Facility, which varies based upon a borrowing base utilization grid. Ultra Resources is also required to pay customary letter of credit and fronting fees.

The RBL Credit Agreement also contains customary affirmative and negative covenants, including, among other things, as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), delivery of quarterly and annual financial statements and oil and gas engineering reports, maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens, indebtedness, asset dispositions, fundamental changes, restricted payments, hedging requirements and other customary covenants.

The RBL Credit Agreement contains customary events of default and remedies for credit facilities of this nature. If Ultra Resources does not comply with the financial and other covenants in the RBL Credit Agreement, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the RBL Credit Agreement and any outstanding unfunded commitments may be terminated.

Term Loan. On April 12, 2017, Ultra Resources, as borrower, entered into a Senior Secured Term Loan Agreement with the Company and UP Energy Corporation, as parent guarantors, Barclays Bank PLC, as administrative agent, and the other lenders party thereto (the “Term Loan Agreement”), providing for senior secured first lien term loans for an aggregate amount of $800.0 million consisting of an initial term loan in the amount of $600.0 million and an incremental term loan in the amount of $200.0 million to be drawn immediately after the funding of the initial term loan.  As part of the Term Loan agreement, Ultra Resources agreed to pay an original issue discount equal to one percent of the principal amount, which is included in deferred financing costs noted in the table above.  Term Loan Agreement has capacity to increase the commitments subject to certain conditions.  

As previously disclosed in a Current Report on Form 8-K filed with the SEC on September 29, 2017, the Company closed an incremental senior secured term loan offering of $175.0 million.  As part of the closing, Ultra Resources agreed to pay an original issue discount equal to 0.25% of the principal amount.  The original issue discount of $0.4 million is included in the deferred financing costs noted above and is a direct deduction from the carrying amount of long-term debt.  At September 30, 2017, Ultra Resources had $975.0 million in outstanding borrowings under the Term Loan Agreement (the “Term Loan Facility”).

The Term Loan Facility bears interest either at a rate equal to (a) a customary London interbank offered rate plus 300 basis points or (b) the base rate plus 200 basis points.  The Term Loan Facility amortizes in equal quarterly installments in aggregate annual amounts equal to 0.25% of the aggregate principal amount beginning on June 30, 2019. The Term Loan Facility matures seven years after the Effective Date.

The Term Loan Facility is subject to mandatory prepayments and customary reinvestment rights. The mandatory prepayments include, without limitation, a prepayment requirement with the total net proceeds from certain asset sales and net proceeds on insurance received on account of any loss of Ultra Resources’ property or assets, in each case subject to certain exceptions. In addition, subject to certain exceptions, there is a prepayment requirement if the asset coverage ratio is less than 2.0 to 1.0. To the extent any mandatory prepayments are required, prepayments are applied to prepay the Term Loan Facility.

The Term Loan Agreement also contains customary affirmative and negative covenants, including as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), delivery of quarterly and annual financial statements and oil and gas engineering reports, maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens, indebtedness, asset dispositions, fundamental changes, restricted payments and other customary covenants. At September 30, 2017, Ultra Resources was in compliance with all of its debt covenants under the Term Loan Facility.

The Term Loan Agreement contains customary events of default and remedies for credit facilities of this nature. If Ultra Resources does not comply with the financial and other covenants in the Term Loan Agreement, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the Term Loan Agreement.

Senior Notes. On April 12, 2017, the Company issued $700.0 million of its 6.875% senior notes due 2022 (the “2022 Notes”) and $500.0 million of its 7.125% senior notes due 2025 (the “2025 Notes,” and together with the 2022 Notes, the “Notes”) and entered into an Indenture, dated April 12, 2017 (the “Indenture”), among Ultra Resources, as issuer, the Company and its subsidiaries, as guarantors. The Notes are treated as a single class of securities under the Indenture.

The Notes have not been registered under the Securities Act of 1933, as amended (the “Securities Act”) or any state securities laws, and unless so registered, the securities may not be offered or sold in the United States except pursuant to an

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exemption from, or in a transaction not subject to, the registration requirements of the Securities Act and applicable state securities laws. The Notes may be resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act or to non-U.S. persons pursuant to Regulation S under the Securities Act.

The 2022 Notes will mature on April 15, 2022. The interest payment dates for the 2022 Notes are April 15 and October 15 of each year, commencing on October 15, 2017. The 2025 Notes will mature on April 15, 2025. The interest payment dates for the 2025 Notes are April 15 and October 15 of each year, commencing on October 15, 2017. Interest will be paid on the Notes from the issue date until maturity.

Prior to April 15, 2019, Ultra Resources may, at any time or from time to time, redeem in the aggregate up to 35% of the aggregate principal amount of the 2022 Notes in an amount no greater than the net cash proceeds of certain equity offerings at a redemption price of 106.875% of the principal amount of the 2022 Notes, plus accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the original principal amount of the 2022 Notes remains outstanding and the redemption occurs within 180 days of the closing of such equity offering. In addition, before April 15, 2019, Ultra Resources may redeem all or a part of the 2022 Notes at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) a make-whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. In addition, on or after April 15, 2019, Ultra Resources may redeem all or a part of the 2022 Notes at redemption prices (expressed as percentages of principal amount) equal to 103.438% for the twelve-month period beginning on April 15, 2019, 101.719% for the twelve-month period beginning April 15, 2020, and 100.000% for the twelve-month period beginning April 15, 2021 and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date on the 2022 Notes.

Prior to April 15, 2020, Ultra Resources may, at any time or from time to time, redeem in the aggregate up to 35% of the aggregate principal amount of the 2025 Notes in an amount no greater than the net cash proceeds of certain equity offerings at a redemption price of 107.125% of the principal amount of the 2025 Notes, plus accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the original principal amount of the 2025 Notes remains outstanding and the redemption occurs within 180 days of the closing of such equity offering. In addition, before April 15, 2020, Ultra Resources may redeem all or a part of the 2025 Notes at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) a make-whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. In addition, on or after April 15, 2019, Ultra Resources may redeem all or a part of the 2025 Notes at redemption prices (expressed as percentages of principal amount) equal to 105.344% for the twelve-month period beginning on April 15, 2020, 103.563% for the twelve-month period beginning April 15, 2021, 101.781% for the twelve-month period beginning April 15, 2022, and 100.000% for the twelve-month period beginning April 15, 2023 and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date on the 2025 Notes.

If Ultra Resources experiences certain change of control triggering events set forth in the Indenture, each holder of the Notes may require Ultra Resources to repurchase all or a portion of its Notes for cash at a price equal to 101% of the aggregate principal amount of such Notes, plus any accrued but unpaid interest to the date of repurchase.

The Indenture contains customary covenants that restrict the ability of Ultra Resources and the guarantors and certain of its subsidiaries to: (i) sell assets and subsidiary equity; (ii) incur indebtedness; (iii) create or incur certain liens; (iv) enter into affiliate agreements; (v) enter into agreements that restrict distribution from certain restricted subsidiaries and the consummation of mergers and consolidations; (vi) consolidate, merge or transfer all or substantially all of the assets of the Company or any Restricted Subsidiary (as defined in the Indenture); and (vii) create unrestricted subsidiaries. The covenants in the Indenture are subject to important exceptions and qualifications. Subject to conditions, the Indenture provides that the Company and its subsidiaries will no longer be subject to certain covenants when the Notes receive investment grade ratings from any two of S&P Global Ratings, Moody’s Investors Service, Inc., and Fitch Ratings, Inc. At September 30, 2017, Ultra Resources was in compliance with all of its debt covenants under the Notes.

The Indenture contains customary events of default (each, an “Event of Default”). Unless otherwise noted in the Indenture, upon a continuing Event of Default, the trustee under the Indenture (“the Trustee”), by notice to the Company, or the holders of at least 25% in principal amount of the then outstanding Notes, by notice to the Company and the Trustee, may, declare the Notes immediately due and payable, except that an Event of Default resulting from entry into a bankruptcy, insolvency or reorganization with respect to the Company, any Significant Subsidiary (as defined in the Indenture) or group of Restricted Subsidiaries (as defined in the Indenture), that taken together would constitute a Significant Subsidiary, will automatically cause the Notes to become due and payable.

Other long-term obligations:  These costs primarily relate to the long-term portion of production taxes payable and asset retirement obligations.

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Cash flows provided by (used in):

Operating Activities.  During the nine months ended September 30, 2017, net cash provided by operating activities was $164.5 million compared to $170.8 million for the same period in 2016. The decrease in net cash provided by operating activities is largely attributable to an increase in interest paid during the nine months ended September 30, 2017, as compared to the same period in 2016, and net changes in working capital.

Investing Activities.  During the nine months ended September 30, 2017, net cash used in investing activities was $374.0 million as compared to $200.1 million for the same period in 2016. The increase in net cash used in investing activities is largely related to increased capital investments associated with the Company’s drilling activities.

Financing Activities.  During the nine months ended September 30, 2017, net cash used in financing activities was $186.6 million compared to net cash provided by financing activities of $368.7 million for the same period in 2016. The change in net cash used in financing activities is primarily due to the restructuring of debt and equity as a result of emergence from chapter 11 proceedings, the movement of $400.0 million from cash to restricted cash for the Reserve Fund, which is for the resolution of make-whole and postpetition interest claims as described in Note 8, and the outflow of deferred financing costs associated with the restructuring of debt and equity.

OFF BALANCE SHEET ARRANGEMENTS

The Company did not have any off-balance sheet arrangements as of September 30, 2017.

CAUTIONARY STATEMENT PURSUANT TO SAFE HARBOR PROVISION OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

This report contains or incorporates by reference forward-looking statements within the meaning of Section 27A of the Securities Act, Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) and the Private Securities Litigation Reform Act of 1995. All statements other than statements of historical facts included in this document, including without limitation, statements in Management’s Discussion and Analysis of Financial Condition and Results of Operations regarding the Company’s financial position, estimated quantities and net present values of reserves, business strategy, plans and objectives of the Company’s management for future operations, covenant compliance and those statements preceded by, followed by or that otherwise include the words “believe”, “expects”, “anticipates”, “intends”, “estimates”, “projects”, “target”, “goal”, “plans”, “objective”, “should”, or similar expressions or variations on such expressions are forward-looking statements. The Company can give no assurances that the assumptions upon which such forward-looking statements are based will prove to be correct nor can the Company assure adequate funding will be available to execute the Company’s planned future capital program.

Other risks and uncertainties include, but are not limited to, fluctuations in the price the Company receives for oil and gas production, reductions in the quantity of oil and gas sold due to increased industry-wide demand and/or curtailments in production from specific properties due to mechanical, marketing or other problems, operating and capital expenditures that are either significantly higher or lower than anticipated because the actual cost of identified projects varied from original estimates and/or from the number of exploration and development opportunities being greater or fewer than currently anticipated and increased financing costs due to a significant increase in interest rates. See the Company’s Annual Report on Form 10-K for the year ended December 31, 2016 for additional risks related to the Company’s business.

ITEM 3 - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Objectives and Strategy:  The Company is exposed to commodity price risk.  The following quantitative and qualitative information is provided about financial instruments to which we were a party at September 30, 2017, and from which we may incur future gains or losses from changes in commodity prices.  We do not enter into derivative or other financial instruments for speculative or trading purposes.  

The Company’s major market risk exposure is in the pricing applicable to its natural gas and oil production. Realized pricing is currently driven primarily by the prevailing price for the Company’s natural gas production. Historically, prices received for natural gas production have been volatile and unpredictable. Pricing volatility is expected to continue.  The prices we receive for our production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index price.  

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The Company relies on various types of derivative instruments to manage its exposure to commodity price risk and to provide a level of certainty in the Company’s forward cash flows supporting the Company’s capital investment program.  These types of instruments may include fixed price swaps, costless collars, or basis differential swaps.  These contracts are financial instruments, and do not require or allow for physical delivery of the hedged commodity.  While mitigating the effects of fluctuating commodity prices, these derivative contracts may limit the benefits we would receive from increases in commodity prices above the fixed hedge prices.

The Company’s hedging policy limits the volumes hedged to not be greater than 50% of its forecasted production volumes without Board approval.  

Fair Value of Commodity Derivatives:  FASB ASC 815 requires that all derivatives be recognized on the Consolidated Balance Sheets as either an asset or liability and be measured at fair value. Changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met.  The Company does not apply hedge accounting to any of its derivative instruments.

Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at fair value on the Consolidated Balance Sheets and the associated unrealized gains and losses are recorded as current expense or income in the Consolidated Statements of Operations. Unrealized gains or losses on commodity derivatives represent the non-cash change in the fair value of these derivative instruments and do not impact operating cash flows on the cash flow statement.  See Note 7 for the detail of the fair value of the following derivatives.

Commodity Derivative Contracts:  At September 30, 2017, the Company had the following open commodity derivative contracts to manage commodity price risk.  For the fixed price swaps, the Company receives the fixed price for the contract and pays the variable price to the counterparty.  For the collars, the Company pays the counterparty if the market price is above the ceiling price and the counterparty pays if the market price is below the floor on a notional quantity.  The reference prices of these commodity derivative contracts are typically referenced to index prices as published by independent third parties.

Natural Gas:

 

 

 

The following table summarizes the pre-tax realized and unrealized gain (loss) the Company recognized related to its derivative instruments in the Consolidated Statements of Operations for the periods ended September 30, 2017 and 2016: 

 

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The realized gain or loss on commodity derivatives relates to actual amounts received or paid or to be received or paid under the Company’s derivative contracts and the unrealized gain or loss on commodity derivatives represents the change in the fair value of these derivative instruments over the remaining term of the contract.

ITEM 4 — CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

The Company has performed an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act as of the end of the period covered by this Quarterly Report. The Company’s disclosure controls and procedures are the controls and other procedures that it has designed to ensure that it records, processes, accumulates and communicates information to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures and submissions within the time periods specified in the SEC’s rules and forms. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those determined to be effective can provide only a reasonable assurance with respect to financial statement preparation and presentation. Based on the evaluation, the Company’s management, including its Chief Executive Officer and Chief Financial Officer, concluded that the Company’s disclosure controls and procedures were effective as of September 30, 2017.

Changes in Internal Control over Financial Reporting

There were no changes in the Company’s internal control over financial reporting during the quarter ended September 30, 2017 that have materially affected or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

 

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PART II — OTHER INFORMATION

ITEM 1.  LEGAL PROCEEDINGS

Other Claims:    See Note 8 for additional discussion of on-going claims and disputes in our chapter 11 proceedings, certain of which may be material. The Company is also currently involved in various routine disputes and allegations incidental to its business operations. While it is not possible to determine or predict the ultimate disposition of these matters, the Company believes that the resolution of all such pending or threatened litigation is not likely to have a material adverse effect on the Company’s financial position, or results of operations.

ITEM 1A.  RISK FACTORS

Our business has many risks.  Any of the risks discussed in this Quarterly Report on Form 10-Q or in our other SEC filings, could have a material impact on our business, financial position, or results of operations.  Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations.  There have been no material changes to the risks described in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016 or the Quarterly Report on Form 10-Q for the period ended March 31, 2017.  This information should be considered carefully, together with other information in this report and other reports and materials we file with the SEC.

ITEM 2.  UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3.  DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4.  MINE SAFETY DISCLOSURES

None.

ITEM 5.  OTHER INFORMATION

(a)  On October 31, 2017, our Compensation Committee approved, and on November 6, 2017, we entered into, employment agreements with each of our officers: Michael D. Watford, Chairman of our Board of Directors and President and Chief Executive Officer; Garland R. Shaw, Senior Vice President and Chief Financial Officer; Brad Johnson, Senior Vice President, Operations; Kent Rogers, Vice President, Drilling and Completions; Patrick Ash, Vice President, Development; and Garrett B. Smith, Vice President, General Counsel and Secretary. The employment agreements are for a term that began on November 6, 2017, the effective date of the agreements, and continues until April 30, 2020, at which point the agreements expire unless we and the officers agree to an extension prior to that date. Each agreement provides that we will pay compensation to the officers, including base salary and cash incentives and equity incentives, and provide employee benefits to the officers, including, for example, health insurance and a 401(k) plan to the same extent as such benefits are available to our other salaried employees, and that the officers will perform their respective duties and obligations for our benefit. Each officer’s title, duties, base salary, target cash incentive amount, target equity incentive amount, and reporting relationship are listed in the agreements and vary based on their respective positions, seniority and other customary market factors and conditions. Any of the foregoing may be augmented (but not diminished) during the term.

Each agreement provides that either we or the officer can terminate the employment relationship during the term. Our right to terminate the employment relationship is subject to our obligation to make certain severance payments and provide certain other benefits to the applicable officer based upon the circumstances prevailing at the time the employment relationship is terminated. We are generally not obligated, under the agreements, to provide any severance payments or benefits if we terminate an officer for cause, and we are generally obligated, under the agreements, to provide the severance payments and benefits specified and as set forth in the agreements if we terminate an officer without cause, if an officer resigns with good reason, if the agreement expires at the end of the term, if we terminate an officer in anticipation, upon or within two years after a change in control, or if, with respect only to Mr. Watford’s agreement, Mr. Watford resigns within two years after a change in control. The amounts of severance payments and benefits we are obligated to provide are set forth in the respective agreements and vary in amount and duration based on each officer’s position, seniority, historical compensation, and other customary market factors and conditions. Our obligation to provide any severance payments or other benefits after a termination of the employment

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relationship is only triggered if the officer timely delivers to us (and does not revoke) a general release of claims against us and all of our affiliates as well as our and their respective employees, officers, directors and shareholders. Each agreement also contains ordinary and customary whistleblower protections, a “valley” provision related to certain excise taxes which may reduce the severance payments and benefits we would otherwise be required to make in connection with a change in control, and various other ordinary and customary covenants for our benefit by the respective officers with respect to inventions, non-solicitation, non-disparagement, confidentiality, and cooperation and assistance with respect to litigation or other adjudicatory proceedings.

The foregoing descriptions of the employment agreements are qualified in their entirety by reference to the full text of the agreements, copies of which are attached hereto as Exhibits 10.8 through 10.13, respectively, and are incorporated herein by reference.

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ITEM 6.  EXHIBITS

(a)  Exhibits

 

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

 

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